Net income available to common shareholders of $0.23 per diluted share and adjusted income available to common shareholders (“Adjusted income”), a non-GAAP financial measure, of $0.06 per diluted share based on total average diluted shares outstanding of 44.2 million shares and an effective tax rate of 37%. Adjusted income excludes certain items that the Company believes affect the comparability of operating results, and are generally non-recurring items or items whose timing and/or amount cannot be reasonably estimated (See “Non-GAAP Financial Measures and Reconciliations” below).

Closing of the previously announced acquisition in the Central Midland Basin on October 8, 2014 and assumption of operatorship of the Casselman and Bohannon fields (the “Ca-Bo” operating area). Callon acquired additional working interests in October 2014 and its current working interest in the fields is 62.7%.

Completion of term debt and common equity financings for a combined $429 million in gross proceeds, contributing to estimated total liquidity of approximately $235 million as of November 1, 2014

Expansion of horizontal development to three zones at the East Bloxom field, with the Neal 658 LH targeting the Lower Wolfcamp B zone from a three-well pad which also included two Upper Wolfcamp B horizontal wells. The Neal 658 LH (7,099′ completed lateral) produced at a peak 24-hour rate of 1,027 BOE/d (80% oil) after being placed on submersible pump, following the cumulative production of 36 thousand BOE under natural flowing pressure over the first 71 days of production.

Expansion of horizontal development to three zones at the Garrison Draw field, with the University 26-35 #15 AH targeting the Wolfcamp A zone from a two-well pad which also included an Upper Wolfcamp B well. The Wolfcamp A (7,472′ completed lateral) produced at a peak 24-rate of 1,449 BOE/d and an average 60-day rate of approximately 595 BOE/d (75% oil) on submersible pump.

Progression of horizontal development of the Lower Spraberry shale, with two wells currently completing in Midland County and one well currently drilling in Upton County

Average total completed well costs of approximately $900 per lateral foot for the latest 10 horizontal wells

Increased fourth quarter 2014 production guidance with a midpoint of 7,400 BOE/d, of which approximately 68% oil and 64% of natural gas volumes are covered by swap contracts sold at an average of $93.58 per barrel of oil and $4.14 per million Btu, respectively.

Operating and Financial Results

Total Revenue. For the quarter ended September 30, 2014, Callon reported total revenues of $39.7 million, comprised of oil revenues of $36.3 million and natural gas revenues of $3.3 million. Average daily production for the quarter was 5,641 BOE/d compared to average daily production of 5,280 BOE/d in the second quarter of 2014. Average realized prices were $85.52 per barrel of oil and $5.86 per Mcf of natural gas in the third quarter of 2014, representing a weighted average of $76.41 per BOE produced.

Lease Operating Expenses, including workover expense (“LOE”). LOE for the three months ended September 30, 2014 was $12.08 per BOE, compared to LOE of $9.08 per BOE in the second quarter of 2014 and $10.68 per BOE for the nine months ended September 30, 2014. The increase in the third quarter was primarily related to elevated workover activity in association with the impact of horizontal well completion operations on surrounding producing wells in certain fields.

Production Taxes, including ad valorem taxes. Production taxes were $4.33 per BOE in the third quarter of 2014, representing approximately 5.7% of total revenue.

Depreciation, Depletion and Amortization (“DD&A”). DD&A for the three months ended September 30, 2014 was $31.05 per BOE compared to $24.96 per BOE in the second quarter of 2014, with the increase in per unit DD&A being attributable to an increased depreciable asset base (the “full cost pool”) relative to estimated proved reserves and an immaterial prior period adjustment. During the quarter, the full cost pool was increased due to the inclusion of the carrying value of our Northern Midland acreage that was previously classified as unevaluated properties. DD&A for the nine months ended September 30, 2014 was $27.76 per BOE.

General and Administrative, net of amounts capitalized (“G&A”). G&A for the three months ended September 30, 2014 was $3.3 million compared to $9.6 million in the second quarter of 2014. The $6.3 million decrease primarily relates to a net decrease of $6.1 million in the mark-to-market valuation of performance-based phantom stock incentive awards period over period. G&A excluding certain non-recurring items and non-cash valuation adjustments (“Adjusted G&A”, a non-GAAP measure) was $4.7 million, or $8.98 per BOE, for the current period and $4.9 million, or $10.25 per BOE, for the second quarter of 2014. Adjusted G&A for the third quarter of 2014 excludes the following items from reported G&A:

$0.1 million in non-recurring, cash expense related to a withdrawn proxy contest

$1.5 million in non-cash gain related to the mark-to-market adjustment of performance-based phantom stock incentive awards

Adjusted G&A for the third quarter of 2014 was comprised of $4.0 million of cash expenses and $0.7 million of non-cash expenses related to stock-based compensation and depreciation and amortization of corporate items. As a result, Adjusted G&A on a cash basis was $7.78 per BOE.

Interest Expense. Interest expense incurred during the three months ended September 30, 2014 increased to $2.2 million compared to $1.8 million in the second quarter of 2014, primarily due to the increase in the balance of our Second Lien Loan.

Income (Loss) Available to Common Shareholders. The Company reported net income available to common shareholders of $10.2 million in the third quarter of 2014 and Adjusted income, a non-GAAP measure, of $2.6 million, or $0.06 per diluted share, which excludes (net of tax effects): (a) $7.7 million in expenses related to the non-cash, mark-to-market valuation of the Company’s derivative positions and phantom stock equity awards and (b) $0.1 million of non-recurring G&A expenses. The Company’s effective tax rate for the third quarter was 37% representative of the statutory rate of 35% adjusted for non-deductible executive compensation expense and state income taxes.

For a definition of Adjusted income and a reconciliation of income (loss) available to common shareholders to Adjusted income, see “Non-GAAP Financial Measures and Reconciliations” below. Adjusting items to arrive at Adjusted income are reflected net of tax at the 35% statutory tax rate.

Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure, for the third quarter of 2014 was $23.0 million. The third quarter of 2014 included $1.8 million for retained asset retirement obligation expenditures related to Gulf of Mexico properties that were sold in the fourth quarter of 2013. Excluding this expenditure attributable to the sold properties, discretionary cash flow from continuing operations was $24.8 million or $0.56 per diluted share.

For a definition of discretionary cash flow and reconciliation to net cash flow provided from operating activities, see “Non-GAAP Financial and Reconciliations” below. No adjustments have been made to discretionary cash flow for non-recurring cash items, such as the asset retirement obligation expenditures described above.

Capital Expenditures

The following table summarizes the Company’s drilling activity in the Permian Basin for the three months ended September 30, 2014:

Drilled

Completed (a)

Awaiting Completion

Gross

Net

Gross

Net

Gross

Net

Southern Midland Basin

Horizontal wells

4

3.5

6

5.3

2

2.0

Total

4

3.5

6

5.3

2

2.0

Central Midland Basin

Vertical wells

1

0.5

2

0.9

—

—

Horizontal wells

3

2.5

—

—

3

2.5

Total

4

3.0

2

0.9

3

2.5

Total vertical wells

1

0.5

2

0.9

—

—

Total horizontal wells

7

6.0

6

5.3

5

4.5

Total

8

6.5

8

6.2

5

4.5

Callon’s total capital expenditures for the third quarter of 2014 are detailed below (in thousands):

In addition, we currently plan to complete two gross (1.3 net) horizontal wells in the fourth quarter on our recently acquired properties in the Central Midland Basin. We forecast these completions will add approximately $5.5 million to our original base operational capital budget.

2014 Guidance

The following fourth quarter 2014 guidance reflects the closing of the Central Midland Basin acquisition on October 8, 2014. Full year guidance, previously provided on August 6, 2014, has been updated for actual results for 2014 to date.

4th Quarter

Full Year

Total production (BOE/d)

7,300 – 7,500

5,400 – 5,600

% oil

76% – 78%

80% – 82%

Expenses (per BOE)

LOE, including workovers

$9.00 – $10.00

$9.50 – $10.00

Production taxes, including ad valorem

$4.00 – $4.75

$4.25 – $4.75

Adjusted G&A, including recurring cash and non-cash items (a)

$7.50 – $8.50

$9.00 – $10.00

(a)

Excludes certain non-recurring expenses and non-cash valuation adjustments. See the reconciliation provided within the Non-GAAP financial measures and reconciliations section of this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense.

Approximately 68% of oil and 64% of natural gas production volumes are hedged based on the midpoint of guidance for the fourth quarter of 2014. In addition, average daily volumes of approximately 3,015 BOE/d and 4,925 MMBtu/d are hedged for calendar year 2015.

Listed below are the outstanding hedges as of November 1, 2014 for the third quarter of 2014 and calendar year 2015.

For the Three Months Ended

December 31,

March 31,

June 30,

September 30,

December 31,

Oil contracts

2014

2015

2015

2015

2015

Collar contracts combined with short

puts (three-way collar):

Volume (MBbls)

—

158

159

—

—

Price per Bbl

Ceiling (short call)

$

—

$

99.10

$

99.10

$

—

$

—

Floor (long put)

$

—

$

90.00

$

90.00

$

—

$

—

Short put

$

—

$

75.00

$

75.00

$

—

$

—

Swap contracts:

Total volume (MBbls)

267

171

136

129

74

Weighted average price per Bbl

$

93.66

$

92.25

$

92.18

$

92.25

$

92.20

Put spreads:

Volume (MBbls)

—

—

—

138

138

Long put price per Bbl

$

—

$

—

$

—

$

90.00

$

90.00

Short put price per Bbl

$

—

$

—

$

—

$

75.00

$

75.00

Swap contracts combined with short put:

Volume (MBbls)

92

—

—

—

—

Swap price per Bbl

$

93.35

$

—

$

—

$

—

$

—

Short put price per Bbl

$

70.00

$

—

$

—

$

—

$

—

For the Three Months Ended

December 31,

March 31,

June 30,

September 30,

December 31,

Natural gas contracts

2014

2015

2015

2015

2015

Collar contracts combined with short

puts (three-way collar):

Volume (BBtu)

—

248

227

207

161

Weighted average price per MMBtu

Ceiling (short call)

$

—

$

4.67

$

4.32

$

4.32

$

4.32

Floor (long put)

$

—

$

4.00

$

3.85

$

3.85

$

3.85

Short put

$

—

$

3.50

$

3.25

$

3.25

$

3.25

Swap contracts:

Total volume (BBtu)

414

271

237

219

228

Weighted average price per MMBtu

$

4.04

$

3.97

$

3.97

$

3.97

$

3.97

Call contracts:

Volume (BBtu)

115

—

—

—

—

Short call price per MMBtu (a)

$

4.75

$

—

$

—

$

—

$

—

Long call price per MMBtu (a)

$

4.75

$

—

$

—

$

—

$

—

Swap contracts combined with short calls:

Swap volume (BBtu)

184

—

—

—

—

Swap price per MMBtu

$

4.25

$

—

$

—

$

—

$

—

Short call volume (BBtu)

—

108

109

110

111

Short call price per MMBtu

$

—

$

5.00

$

5.00

$

5.00

$

5.00

(a)

Offsetting contracts.

Non-GAAP Financial Measures and Reconciliations

This news release refers to non-GAAP financial measures as “discretionary cash flow,” “Adjusted income,” “Adjusted G&A” and “Adjusted EBITDA.” These measures, detailed below, are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

Callon believes that the non-GAAP measure of discretionary cash flow is useful as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt. The Company also has included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and may not relate to the period in which the operating activities occurred.

We believe that the non-GAAP measure of Adjusted income and Adjusted income per diluted share are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. These measures exclude the net of tax effects of certain non-recurring items and non-cash valuation adjustments, which are detailed in the reconciliation provided below. Prior to being tax-effected and excluded, the amounts reflected in the determination of Adjusted income and Adjusted income per diluted share below were computed in accordance with GAAP.

Callon believes that the non-GAAP measure of Adjusted G&A is useful to investors because it provides readers with a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period. The table below details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A.

We calculate Adjusted Earnings before Interest, Income Taxes, Depreciation, Depletion and Amortization (“Adjusted EBITDA”) as Adjusted income plus interest expense, income tax expense (benefit) and depreciation, depletion and amortization expense. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), cash flow provided by operating activities or other income or cash flow data prepared in accordance with GAAP. However, we believe that Adjusted EBITDA provides additional information with respect to our performance or ability to meet its future debt service, capital expenditures and working capital requirements. Because Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and may vary among companies, the Adjusted EBITDA we present may not be comparable to similarly titled measures of other companies.

Includes $1,814, $1,443 and $86 of asset retirement obligations related to discontinued Gulf of Mexico operations in the three month periods ended September 30, 2014, June 30, 2014, and September 30, 2013, respectively.

The following tables reconcile income (loss) available to common stockholders to Adjusted income (in thousands; reconciling items are reflected net of tax):

Three Months Ended

September 30, 2014

June 30, 2014

September 30, 2013

Income (loss) available to common stockholders

$

10,227

$

2,767

$

(892)

Net loss (gain) on derivative contracts, net of settlements

(6,764)

1,975

1,984

Phantom stock mark-to-market, net of settlements

(974)

2,982

1,253

Withdrawn proxy contest expenses

65

85

—

Gain on early redemption of debt

—

(2,083)

—

Adjusted income

$

2,555

$

5,726

$

2,345

Adjusted income per fully diluted common share

$

0.06

$

0.14

$

0.06

The following tables reconcile net income (loss) to Adjusted EBITDA (in thousands) for the periods indicated:

Three Months Ended

September 30, 2014

June 30, 2014

September 30, 2013

Net income

$

12,201

$

4,740

$

1,082

Net loss (gain) on derivative contracts, net of settlements

(10,406)

3,039

3,052

Non-cash stock-based compensation expense

(1,031)

4,105

2,529

Gain on early redemption of debt

–

(3,205)

–

Withdrawn proxy contest expenses

100

130

–

Income tax expense

7,161

4,128

456

Interest expense

2,205

1,825

1,417

Depreciation, depletion and amortization

16,517

12,378

12,263

Accretion expense

202

173

458

Adjusted EBITDA

$

26,949

$

27,313

$

21,257

The following tables reconcile total G&A to Adjusted G&A (in thousands) for the periods indicated:

Three Months Ended

September 30, 2014

June 30, 2014

September 30, 2013

Total G&A

$

3,261

$

9,639

$

5,826

Withdrawn proxy contest

(100)

(130)

–

Mark-to-market valuation adjustment of performance

-based phantom stock incentive awards

1,499

(4,587)

(1,928)

Adjusted G&A

$

4,660

$

4,922

$

3,898

The following table presents summary information for the periods indicated, and are followed by the Company’s financial statements.

Three Months Ended

September 30, 2014

June 30, 2014

September 30, 2013

Net production:

Oil (MBbls)

425

405

257

Natural gas (MMcf)

565

452

864

Total production (MBOE)

519

480

402

Average daily production (BOE/d)

5,641

5,280

4,418

% oil (BOE basis)

82%

84%

64%

Average realized sales price:

Oil (Bbl) (excluding impact of cash settled derivatives)

$

85.52

$

93.10

$

105.11

Oil (Bbl) (including impact of cash settled derivatives)

84.35

89.24

102.71

Natural gas (Mcf) (excluding impact of cash settled derivatives)

$

5.86

$

6.17

$

4.38

Natural gas (Mcf) (including impact of cash settled derivatives)

5.92

6.01

4.36

Total (BOE) (excluding impact of cash settled derivatives)

$

76.41

$

84.30

$

76.61

Total (BOE) (including impact of cash settled derivatives)

75.52

80.95

75.03

Oil and natural gas revenues (in thousands):

Oil revenue

$

36,346

$

37,710

$

27,014

Natural gas revenue

3,311

2,792

3,783

Total

$

39,657

$

40,502

$

30,797

Additional per BOE data:

Sales price

$

76.41

$

84.30

$

76.61

Lease operating expense

12.08

9.08

13.11

Production taxes

4.33

4.71

2.47

Operating margin

$

60.00

$

70.50

$

61.03

Other expenses per BOE:

Depletion, depreciation and amortization

$

31.05

$

24.96

$

29.62

Adjusted G&A (a)

8.98

10.25

9.70

(a)

Excludes certain non-recurring expenses and non-cash valuation adjustments. See the reconciliation provided within the Non-GAAP financial measures and reconciliations section of this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense.

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